Deepwater Frac-Pack Maximum Treating Pressure Limits, An Examination Using Bottomhole Pressure Gauges

摘要

During frac-pack treatments, completion hardware is often subject to extreme differential pressures. This is especially true during early screenouts where the large hydrostatic differentials can suddenly be placed on the completion components, resulting in a high risk of collapse. Deep wells and completion-tool configuration can limit supporting pressures for these tools. To prevent damage to completion hardware such as crossover tools, fluid-loss devices, and blank pipe, the maximum surface treating pressure has been limited to a calculated Pmax (Jannise and Edwards 2007). Conventionally, the reservoir pressure was used as the internal supporting pressure in these calculations. Using the reservoir pressure to calculate the Pmax results in a worst-case pressure limit that prevents collapse in virtually any job. However, today many frac-pack treatments are being performed in low-pressure, subhydrostatic reservoirs. Many of these jobs could not be placed using just reservoir pressure for support, even when using high-strength, completion hardware materials. By analyzing a significant number of actual jobs, it was determined that the current standard equatipns are too conservative when compared to actual treating results. By using less conservative, modified equations, numerous additional wells have been completed with frac-pack technology. This paper studies a number of these successful frac-pack jobs that could not have been performed using the standard Pmax equation and safety factors. Postjob bottomhole-gauge data are examined to determine the true differential pressures and verify the accuracy of the assumptions that are used in the modified Pmax calculation, which provides valuable insight and recommendations for tool design, fluid properties, and maximum-pressure limitations for frac-pack completions.